Field of the Invention
Embodiments of the present invention generally relate to a system and method of sealing a tubular during a cementing operation. More particularly, the present invention relates to a releasable plug that may be released from a device, such as a cement plug, into a float assembly, which in turn, seals a casing from an annulus of a wellbore.
Description of the Related Art
A wellbore is formed by using a drill bit on a drill string to drill through a geological formation. After drilling through the formation to a predetermined length or depth, the drill string and drill bit are removed, and the wellbore is lined with a string of casing. The space between the outer diameter of the casing and the wellbore is referred to as an annulus. In order to prevent the casing from moving within the wellbore, the annulus is filled with cement using a cementing operation. In addition to preventing the casing from moving within the wellbore, the cemented annulus also provides for a stronger wellbore for facilitation of hydrocarbon production.
When the casing is sent downhole, the casing is typically filled with a fluid, such as drilling mud, and the fluid is maintained at a predetermined pressure. The fluid within the casing ensures that the casing does not collapse within the wellbore. A bottom end of the casing usually includes a float assembly, such as a float collar or a float shoe. The float assembly includes one or more unidirectional check valves that allow fluid to pass from the casing out to the annulus, but prevents fluid from entering from the annulus into the casing. An upper end of the float assembly may also include a receptacle for receiving a device, such as a cement plug.
During a cementing operation, it is preferred that the cement is isolated or separated from any other fluid within the casing. When fluids such as drilling mud mix with cement, it can cause the cement to sour and fail when it sets. Accordingly, a first plug is usually sent down in front of the cement during a cementing operation. The first plug includes one or more fins around its circumference which acts to separate the drilling fluid below the first plug from the cement above the first plug. The fins also clean the inner walls of the casing as the first plug descends into the casing. Because the first plug provides both a separation and cleaning function, the outer diameter of the first plug is approximately equal to the inner diameter of the casing. The first plug includes a bore through a center longitudinal portion of the first plug. The first plug also includes a rupture membrane, such as rupture assembly, radially positioned across the bore, which prevents the drilling fluid below the first plug from comingling with the cement above the first plug. As the first plug descends into the casing, the drilling fluid moves through the float assembly and out into the annulus. The check valve within the float assembly prevents the drilling fluid from moving back into the casing.
Once the first plug reaches the float assembly, hydrostatic pressure builds on the upper side of the rupture membrane. Once the first plug reaches a rupture pressure, the rupture membrane ruptures, and the cement flows through the bore of the first plug, through the float assembly, and into the annulus. The check valve within the float assembly prevents the cement from moving back into the casing.
A second plug is usually sent down the casing behind the cement, and the second plug is usually pushed downward with drilling fluid. The second plug includes one or more fins that separate the cement below the second plug from the drilling fluid above the second plug. The fins also clean the sidewalls of the casing as the second plug descends down the casing. The second plug generally does not include a bore within a center portion. As the second plug is pushed through the casing, the cement is squeezed out of the float assembly into the annulus until the second plug reaches the first plug. In some embodiments, the first plug and second plug are locked together. In the prior art, at least one of the first or second plugs form a seal within the casing, which prevents fluid from moving past the first or second plugs. Once the wellbore is sealed, the cement is given time to cure and set up as a constant pressure is maintained within the casing. Before or after the cement has cured, the casing is pressure tested by injecting additional drilling fluid into the casing up to a casing operational pressure, which is then held for a certain time period in order to establish the back pressure capabilities of the casing.
The length and depth of oil and gas wells continues to increase, which results in high temperatures and high pressures within the casing. As a result, the casing required to line deeper oil and gas wells includes an increased diameter. In order to perform cementing operations in the extended diameter casings, the plugs used in cementing operations must also have an increased diameter, and must also be comprised of materials that may withstand high temperature and high pressure. Accordingly, the materials required for larger diameter plugs are often expensive. In addition, an adequate seal in the wellbore is required following a cementing operation, and obtaining a seal with extended diameter plugs is difficult to achieve. Because sealing the casing is difficult to achieve, there is difficulty in pressure testing the cemented casing to prove up its mechanical integrity.
Therefore, there is a need for a more effective system and method for sealing a wellbore during cementing operations.